Trinidad and Tobago is well equipped to handle new challenges

The Caribbean island state of Trinidad and Tobago is no newcomer to the oil and gas business. It has been producing hydrocarbons for more than a century, with commercial production of crude oil dating back to 1908. Although a small country, and comparatively speaking a small producer, its long and rich experience in the industry has helped the country punch above its weight in regional and even world terms.

In 2013 T&T produced 1.5trn cu feet (tcf) of natural gas, according to the 2015 “Trinidad and Tobago Energy Map”, helping to rank it as the world’s sixth-largest liquefied natural gas (LNG) exporter and largest LNG supplier to the US. The country is also the world’s largest exporter of ammonia and the second-largest exporter of methanol. In recent years natural gas has overtaken oil production in importance. On an energy equivalence basis, T&T now produces around nine times as much natural gas as it does oil. Crude oil production has been declining, from a 2005 high of 144,674 barrels per day (bpd) to 81,278 bpd in 2013, reflecting maturing oilfields and operational challenges.

According to Kevin Ramnarine, head of the Ministry for Energy and Energy Affairs (MEEA), 2014 crude oil output was 81,100 bpd, similar to 2013. Meanwhile, natural gas production surged strongly in the first decade of the new millennium, multiplying by a factor of four to reach 1.44 tcf in 2009, up from 414.24bn cu feet (bcf) in 1999. Gas production plateaued after 2010 – a phenomenon attributed to unattractive fiscal terms offered on exploration and production (E&P) licences that caused underinvestment between 2008 and 2010. However, after confrontation with the industry, the government reconsidered its position. The terms were made more generous, and upstream investment began to flow again, supporting expectations that production will, in due course, resume a growth path.

Three Phases

The T&T hydrocarbons industry has gone through three distinct E&P phases. The first and easiest phase on the southern half of Trinidad involved using rudimentary geological methods, such as field mapping and detecting onshore seeps. In some cases the oil was simply there to be discovered, as evidenced by the La Brea Pitch Lake, considered one of the largest natural asphalt deposits in the world and said to have been used by Sir Walter Raleigh to caulk his ships in the late 16th century. The second phase saw the introduction of more sophisticated geophysical survey methods and the development of offshore crude oil, followed by gas wells in west and east Trinidad’s shallow waters and in deeper northern waters. The third and current phase involves unexplored deepwater acreage (see analysis), unconventional deposits and the re-examination of all blocks using new technology to increase recovery rates from existing reservoirs.

State officials and industry executives are confident that the country has the necessary reserves to permit ongoing hydrocarbons production and exports. In November 2014 Ramnarine signed E&P agreements for three onshore blocks as part of a licensing round launched in 2013. Licences were awarded to Touchstone Exploration, Range Resources and Lease Operators, covering an area equivalent to 12.5% of T&T’s land mass. “Increasing the number of horizontal wells and other recovery operations will help optimise production among onshore wells. Enhancing incentives that encourage operators to implement new technologies will further improve production,” Michael Loewen, country manager of Touchstone Exploration, told OBG.

After signing new exploration licence deals in November 2014, Ramnarine told local press, “We believe that when we have production coming from these three blocks, we will see oil production in T&T go back to more than 100,000 bpd, which is where we were some five years ago.” The government was also hopeful over deep-water oil production prospects and the contribution of enhanced oil recovery techniques.

Price Factor

In April 2015 Ramnarine reported to Parliament that in the preceding five years the MEEA entered into 12 production-sharing contracts (PSCs) and granted nine E&P licences. Further onshore and offshore licensing rounds were being considered for 2015, but officials admitted the sharp drop in international crude oil prices in the second half of 2014 and early months of 2015 might put those plans on hold.

On the plus side, both government officials and private sector oil companies noted that T&T had been through oil price booms and slumps before. The industry is accustomed to adapting and has traditionally shown considerable resilience. Clifford Lackhansingh, general manager of the Trinidad office of US engineering firm FLUOR, told OBG, “Energy contractors and service companies that have adopted conservative policies in the past few years and diversified their portfolio of operations are in a relatively comfortable situation in the current low-commodity-price environment.”

Tax Changes

Thackwray Driver, presid ent and CEO of the Energy Chamber of T&T, agreed on the resilience of the local oil and gas sector. He said that four to five years previously the governm ent sought to tax offshore contracts too heavily. Each of the new PSCs has its own fiscal take, negotiated case-by-case. However, for E&P licences there is a basic 55% tax on profits plus royalties, and a supplemental petroleum tax, which works on a sliding scale linked to international prices. Previously, the government found that some international oil majors were staying away. “To stimulate deep-water, T&T had to significantly reduce the government take on PSCs. When it did that, we attracted investment from BHP and others,” Driver told OBG. “Trinidad has had gas shortages for the past few years, because we had a period of underinvestment when we got the tax wrong. We taxed our way out of being competitive.” In his view, to feed LNG exports and downstream industries, T&T must boost gas production from the current 4 bcf per day (bcfd) to 4.2 bcfd (see analysis).

Executives at BP T&T (BPTT) agreed that the fiscal changes have been key to encouraging investment. The company was the first to be awarded a deepwater PSC in addition to the E&P licence in the Juniper block, which it said would not have been feasible without changes to the fiscal structure. The Central Bank of T&T (CBTT) also recognised the importance of the changes, commenting in a January 2014 report that “adjustments to the tax legislation have created a more competitive industry which has attracted greater global interest in T&T’s onshore and marine acreage”.

In early 2015 T&T became a full member of the Extractive Industries Transparency Initiative (EITI). Clare Short, chair of the EITI board, said that the country had submitted an “impressive” detailed report on its tax regime and licensing requirements (see analysis).

Keeping Up

T&T also needs to remain competitive relative to other oil-producing countries in the region, like Colombia or Mexico. In 2015 Mexico opened up its oil and gas sector to private companies for the first time in seven decades. However, the local industry agrees that T&T has at least five important factors working in its favour. First, in term of geology the country remains a great hydrocarbons province. Second, it has a long history in the industry, which faces no domestic social opposition. Third, successive governments have been open to foreign investment, a policy position that is not expected to change, and many in the industry perceive no danger of nationalisation. Fourth, there is strong respect for the rule of law and commercial contracts. Lastly, the country has well-developed service industries and well-trained technicians and workers.

Making New Plans

Looking forward, it is clear that gas will continue to play a key role in the industry’s development. Recognising this, in November 2014 the MEEA hired UK-based consultancy Poten & Partners to work on a Gas Master Plan for 2014-24, to be delivered in the course of 2015. Ramnarine told local press, “There is critical work to be done in the natural gas sector in the next four to five years. Before we make those decisions, we should at least have very robust and studied research done. That is why it fits to have a Natural Gas Master Plan to guide policy for the next 10 years.”

Among the issues to be considered are the demand-supply imbalance, the correct allocation between domestic gas use and exports, and ways to incentivise upstream players. In addition, the industry is looking at the medium-term development of cross-border gas fields with Venezuela. The Loran-Manatee field has proven reserves of over 10 tcf, of which 73% belong to Venezuela and 27% to T&T. A framework agreement between the two governments was signed in 2013, with further agreements on energy cooperation and the unitisation of the 740-bcf Cocuina Manakin cross-border gas field, signed in February 2015.

Ramnarine told OBG the Loran-Manatee field could become productive over the next three to five years, and the four operating companies – PDVSA, Petrotrin, Chevron and BG Group – are currently discussing commercialisation arrangements, with Chevron holding a share in both the Venezuelan and T&T sides of the field. T&T is hoping to leverage the sound gas-processing infrastructure it already has in place to monetise a larger share than is currently agreed upon.

Structure

The oil and gas sector lies at the very heart of the T&T economy. In 2014 the industry accounted for around 42% of GDP at current prices, according the CBTT’s “Annual Economic Survey 2014”. In terms of foreign trade, energy made up 85% of exports and nearly 47% of imports in the same year. For the public sector, the energy industry provided some 48.1% of state revenues. The sector had a less direct impact on the labour market, as it is a capital-intensive industry: oil and gas is responsible for around 3.3% of total employment. The industry relies on active state-owned enterprises and on a dynamic private sector, including both oil majors and smaller independents.

Despite ongoing discussions over a variety of issues, such as appropriate taxation levels and incentives, the relationship between public and private sector players in the industry has been traditionally collaborative. In a number of cases the government has made investments in infrastructure and processing plants that at a later stage have been spun off to private operators.

Letter of the Law

The regulatory framework is set by the Petroleum Act (1969), the Petroleum Regulations Law (1970) and the Petroleum Taxes Act (1974). Together, these laws allow for the government to grant licences and contracts for oil and gas E&P onshore and in marine areas in T&T’s territorial waters. The decision to invite applications for E&P rights on a competitive basis in specific areas lies with the MEEA. The ministry is also charged with regulating and “giving broad direction and guidance” to the industry.

Four types of licences and contracts can be offered: exploration licences (Public Petroleum Rights) give licensees non-exclusive rights to carry out operations; E&P licences (Public Petroleum Rights) give exclusive rights to the licensees to explore, produce and dispose of petroleum; E&P licences (Private Petroleum Rights); and PSCs. These are now the most commonly used contracts, setting terms for exploration, production and sale. While E&P contracts prevailed before 1990, after that date there was an increasing move to PSCs. After 2005 so-called taxable PSCs have been used, where the government receives a share of profits in lieu of some taxes, but others remain payable. The contracts also included a windfall profits feature triggered by high international oil prices. A third feature was that PSCs could be consolidated by type (shallow water, deepwater or onshore). This was permitted as part of the government’s intention to promote multi-block development and allow consortia to greater share risk.

A new petroleum fiscal regime was introduced in 2010, removing the taxable PSCs and replacing them with more conventional PSCs that sought to provide greater fiscal stability to the companies while still retaining the windfall profits feature. In addition, the new regime introduced a simpler competitive bidding process as well as amendments to the supplemental petroleum tax structure and the sub-licence arrangement provisions in marine areas. Further fiscal incentives were then introduced in 2013 and 2014.

Industry Players

The key upstream players in T&T include private sector firms such as BPTT, BG Group, Texas-based EOG Resources, Spain’s Repsol, Chevron and Australia’s BHP Billiton. BPTT is 70% controlled by UK-based BP, with Repsol holding the minority 30% stake. BP also has a stake in Atlantic, the gas liquefaction and export company.

A major player in the local industry, BPTT accounts for 66% of T&T’s gas output. It is pushing ahead with its Juniper offshore gas project, expected to come online in 2017 with 590m cu feet per day, representing an increase of up to one-third of its gas production.

BHP operates the Greater Angostura oil and gas field, in which it holds a 45% stake. It has also taken a 70% stake in two BPTT blocks – T&T Deep Atlantic Areas 14 and 23(a) – with BPTT retaining an interest as a non-operator. BG Group produces gas from the Dolphin, Hibiscus, Poinsettia and Chaconia gas fields. It also has a stake in Atlantic. In December 2014 the company started gas production from its Starfish field, in which it has a 50% stake, alongside Chevron with the other 50%.

Trinidad has two oil terminals – Pointe-à-Pierre and Galeota – while Tobago has one, at Scarborough on the south coast of the island. There is an extensive oil and gas pipeline network on Trinidad, although there was concern over a number of oil pipeline leaks in 2013 around the Pointe-à-Pierre refinery.

Gas

Natural gas is delivered by pipeline to a range of processing plants. The state-owned National Gas Company (NGC) plays an important role, and owns, maintains and operates the country’s onshore and offshore pipeline network, extending for about 1000 km and with a pumping capacity of 4.4 bcfd. While NGC has no direct upstream operations, it aggregates, transports and distributes raw gas to processors and to Atlantic, as well as having a wider remit of promoting and facilitating gas-based investment. Also important, Phoenix Park Gas Processors Limited (PPGPL), 90% owned by NGC, purifies raw natural gas to supply downstream customers, and uses extracted natural gas liquids for the production of propane, butane and petrol. PPGPL has a 45% share of the Caribbean market for propane and butane. Conoco Phillips previously held a 39% stake in PPGPL, which it sold to NGC, bringing the latter’s holding up to 90%. However, the government subsequently approved a decision to float half of the newly acquired shares (19.5%) through an initial public offering (IPO). The IPO was expected to happen in 2015.

One of the most important processors is the Atlantic terminal, which has four liquefaction trains with a combined total capacity of nearly 15m tonnes per annum. While there have been discussions on building a fifth, or even sixth, train, signs of weaker LNG import demand from the US have cooled investor interest. Atlantic has around 524,000 cu metres of LNG storage capacity.

The Tobago pipeline, which connects the smaller island’s Cove Industrial Estate to Trinidad’s main gas fields, became operational in 2012. Since 2010 discussions on an inter-Caribbean gas pipeline, which would connect T&T to Barbados and other Windward Islands in the Lesser Antilles, have been making some progress. Plans have also been discussed for a separate pipeline connection to Grenada and St Vincent and the Grenadines. T&T has a network of around 200 petrol service stations – the majority of which are owned by the National Petroleum Marketing Company. Unipet operates a second chain.

Refineries & Distribution

Petrotrin is active in upstream and in refining, but not in retail distribution. In the upstream segment it has several 100% controlled onshore and marine licences, mainly in south and southwest Trinidad. From these sources, as well as third-party associations and farm-outs, in 2014 Petrotrin had an estimated crude oil production of 45,663 bpd. The firm operates one of the Caribbean’s main refineries at Pointe-à-Pierre in Trinidad, with an annual capacity of 168,000 bpd. It uses its own indigenous crude as feedstock to supply the refinery, but must also import around 100,000 bpd, which it acquires from a range of suppliers including Colombia, West Africa, Russia and Brazil, depending on oil grades needed and prices.

Petrotrin’s management team told OBG that in effect it runs two parallel businesses, an upstream E&P business, which is normally profitable (although it comes under some duress when international crude prices fall) and a refining business that faces longer-term pressures on its margins. Khalid Hassanali, president of Petrotrin, notes that US mid-continent and Gulf coast refineries, which now have better access to advantage (indigenous) crude and cheap gas because of shale, have been supplying the Caribbean with refined products at low prices. “When you look at what is happening with the US refining sector, you will see that since 2012 they have switched from being a net importer of fuel to a net exporter of refined fuels, so the US refining system is exporting tremendous amounts of gasoline and diesel, which has more than replaced whatever capacity we lost from the refineries that were shut down in the Caribbean,” Hassanali told OBG. As a result, Petrotrin will concentrate on controlling costs and improving efficiencies at its own refinery. Petrotrin might also benefit from the possible winding down of Venezuela’s PetroCaribe programme, which has offered subsidised fuel to Caribbean and Central American countries.

Fuel Subsidy

Although the government could count on a number of financial buffers, the sharp downturn in hydrocarbons prices in late 2014 and early 2015 was widely seen as prompting a range of necessary fiscal austerity measures. In this context a number of analysts raised the issue of whether T&T’s fuel subsidies might need to be reviewed. Traditionally, the government has provided a subsidy by setting low fixed petrol and diesel prices at service stations, and then importing crude at fluctuating international prices to meet roughly two-thirds of Petrotrin’s refinery needs.

In January 2015 an IMF mission visiting T&T said that the fall in international hydrocarbons prices constituted “a major challenge” for the country, and welcomed the government’s decision to recast the budget using more conservative oil and gas price assumptions. In a press release IMF mission leader Elie Canetti added, “We reiterate our advice to scale down fuel subsidies, and note that the fall in global energy prices provides a unique opportunity to do this.”

At the end of the same month, Larry Howai, minister of finance and the economy, told OBG that the government was considering either reducing or removing the fuel subsidy, but first wanted to improve the local supply of compressed natural gas (CNG). Howai also told the local press that the build-out of CNG capacity throughout the country would be completed by the first half of 2016 and that this was “a pre-requisite for consideration of the removal of the fuel subsidy”.

Major Drain

The fuel subsidy was estimated to have totalled around TT$4bn ($616.8m) in 2013. At the beginning of 2015, Prime Minister Kamla Persad-Bissessar said that because of the fall in international crude oil prices, the government was likely to save TT$2bn ($308.4m) on lower subsidy payments. Howai also told OBG, “We are projecting the amount of fuel subsidy for 2015 to be close to TT$1.6bn-1.7bn [$246. 72m-262.14m] as a result of the lower oil prices.”

In February 2015 super-grade petrol was priced at TT$2.80 ($0.43). For rough comparison, this was around 18% of the average price in the US and 6.8% of the price in UK for the same period, according to the US Energy Information Administration (EIA). Ronald Milford, CEO of Unipet, argued that the time was right for a phased and further reduction of the subsidy, perhaps by some 50% in stages over three to four years.

Power Sector

Electricity in T&T is almost entirely produced by generators burning natural gas. Gross power generation in 2013 was 7.9 TWh, down from a peak of 8.9 TWh in 2011, according to the EIA. In late 2013 the government commissioned a second combined-cycle, gas-fired power plant with a 720-MW capacity. The country’s 440,000 residential and industrial electricity customers are supplied by the state-owned T&T Electricity Commission (T&TEC), which buys from three independent power producers (IPPs). As with petrol, T&TEC subsidises electricity, by negotiating a special price for natural gas provided by state-owned NGC to the IPPs. In late 2014 Kelvin Ramsook, general manager of T&TEC, told the local press that this price stood at $1.18 per million British thermal units (Btu), roughly a third of prevalent market prices. By controlling the price of gas used by the IPPs, T&TEC is able to control the end price for consumers.

Low electricity costs are considered an important comparative advantage for companies operating in T&T. According to investment promotion agency InvesTT, the country has the world’s eighth-lowest electricity cost per KWh. Ramesh Ramdeen, chief executive of the T&T Manufacturers’ Association, told OBG, “Here in Trinidad we are paying $0.04 per MWh of energy, while they have to pay $0.37 in Jamaica. Our energy bills represent only 5-10% of total manufacturing costs.” However, according to the Inter-American Development Bank, combined fuel and electricity subsidies could represent more than 6% of GDP and favour the wealthy, who consume more energy per capita.

In October 2014 a series of power outages in western Trinidad including the capital, Port of Spain, were attributed to a shutdown for technical reasons at PowerGen, one of the IPPs. T&TEC said it was working to increase the resilience of the network and meet rising demand. It was expecting the new 720-MW plant commissioned from another IPP, Trinidad Generation Unlimited, to make a difference, but even taking that into account, additional capacity would be needed by 2020.

Renewables

Renewable energy sources, mainly biomass and waste, represent an almost negligible share of energy supply. Of the 872trn Btu of primary energy consumption in 2013, natural gas provided 92% and petroleum products the remaining 8%. However, the government has expressed interest in developing renewables and launched a number of pilot projects.

Since 2013 the MEEA has been working on setting up a Regional Renewable Energy Centre. A pilot solar thermal project has been launched across 25 schools. The new Wind Resource Assessment Programme on the east coast of Trinidad was also approved to assess the feasibility of establishing a wind turbine farm.

After attending the First Caribbean Energy Security Summit in Washington, DC, in January 2015, PersadBissessar proposed setting up a regional energy security fund for CARICOM member states. She suggested a three-pronged approach consisting of: improving conservation and energy efficiency; maximising the use of renewable energy sources; and converting to LNG-fuelled electricity generation.

Outlook

Like most oil and gas producers around the world, T&T faced a degree of uncertainty in early 2015 due to the slump in international oil prices. The downturn coincided with a number of medium- to long-term structural challenges. These included: the curtailments in gas production caused by a dip in E&P activity in previous years; the need to reverse the fall in oil production; the need to develop technically and financially complex deepwater deposits in both oil and gas; and a serious margins squeeze on Petrotrin’s refinery business caused in part by the shale revolution in the US.

While these issues will take time to resolve, it is also important to stress T&T’s strong fundamentals. The local industry has been through oil and gas downturns in the past, and the country has a number of financial buffers. While exploration and development is shifting to deepwater, underlying reserves remain plentiful and attractive. The policy environment remains supportive of foreign investment, and despite the slump in global hydrocarbons prices, oil majors continue to pursue significant capital expenditure programmes. While the industry will have to show some resilience in 2015, there is a strong prospect of a return to growth in 2016.